In drilling a borehole into the earth, such as for the recovery of hydrocarbons (e.g., crude oil and/or natural gas) from a subsurface formation, it is conventional practice to connect a drill bit onto the lower end of an assembly of drill pipe sections connected end-to-end (commonly referred to as a “drill string”), and then rotate the drill string so that the drill bit progresses downward into the earth to create the desired borehole. A typical drill string also incorporates a “bottom hole assembly” (“BHA”) disposed between the bottom of the drill pipe sections and the drill hit. The BHA is typically made up of sub-components such as drill collars and special drilling tools and accessories, selected to suit the particular requirements of the well being drilled. In conventional vertical borehole drilling operations, the drill string and hit are rotated by means of either a “rotary table” or a “top drive” associated with a drilling rig erected at the ground surface over the borehole.
During the drilling process, a drilling fluid (commonly referred to as “drilling mud”) is pumped downward through the drill string, out the drill bit into the borehole, and then back up to the surface through the annular space between the drill string and the borehole. The drilling fluid carries borehole cuttings up to the surface while also performing various other functions beneficial to the drilling process, including cooling the drill bit cooling and forming a protective cake on the borehole wall (to stabilize and seal the borehole wall).
As an alternative to rotation by a rotary table or a top drive, a drill bit can also be rotated using a “downhole motor” (alternatively referred to as a “drilling motor” or “mud motor”) incorporated into the drill string immediately above the drill bit. The mud motor is powered by drilling mud pumped under pressure through the mud motor in accordance with well-known technologies. The technique of drilling by rotating the drill bit with a mud motor without rotating the drill string is commonly referred to as “slide” drilling, because the non-rotating drill string slides downward within the borehole as the rotating drill bit cuts deeper into the formation. Torque loads from the mud motor are reacted by opposite torsional loadings transferred to the drill string.
Downhole motors are commonly used in the oil and gas industry to drill horizontal and other non-vertical boreholes (i.e., “directional drilling”), to facilitate more efficient access to and production from more extensive regions of subsurface hydrocarbon-bearing formations than would be possible using vertical boreholes.
It is very common for a BHA to incorporate a reaming tool (“reamer”) and/or a stabilizer tool (“stabilizer”). Reaming may be required to enlarge the diameter of a borehole that was drilled too small (due perhaps to excessive wear on the drill bit). Alternatively, reaming may be needed in order to maintain a desired diameter (or “gauge”) of a borehole drilled into clays or other geologic formations that are susceptible to plastic flow (which will induce radially-inward pressure tending to reduce the borehole diameter). Reaming may also be required for boreholes drilled into non-plastic formations containing fractures, faults, or bedding seams where instabilities may arise due to slips at these fractures, faults or bedding seams. A stabilizer, following closely behind the drill bit, is commonly used to keep drill string components (including the drill bit) centered in the borehole. This function is particularly important in directional drilling, in order to keep a borehole at a particular angular orientation or to change the borehole angle.
Numerous and varied types of reamers and stabilizers are known in the prior art. Representative examples of prior art reamers and stabilizers may be seen in U.S. Pat. No. 4,385,669 (Knutsen); U.S. Pat. No. 5,474,143 (Majkovic); and U.S. Pat. No. 6,213,229 (Majkovic). In prior art reamers, however, the cutting elements are effective to increase or maintain a borehole diameter only when the drill string is rotating; similarly, the centralizing elements of prior art stabilizers are effective for their purpose only when the drill string is rotating. This is because the cutting elements and centralizing elements of prior art reamers and stabilizers are typically fixed to the corresponding tool bodies, so they rotate about the longitudinal axis of the tool. As a result, the cutting and centralizing elements tend to wear evenly, which allows the reamers and stabilizers to remain effect for their respective purposes despite a certain degree of wear. However, in cases where a non-rotating drill string is being moved axially with a wellbore (such as in slide drilling and in “tripping” operations), the cutting and centralizing elements of known reamers and stabilizers do not rotate, which causes these elements to wear unevenly as they scrape against the sidewalls of the borehole.
For these reasons, there is a need for reamers and stabilizers that are effective for their respective purposes in a drill string that is being moved axially within a wellbore but without rotation. The present invention is directed to this need.